European gas prices climbed through the summer, with the TTF benchmark averaging about €44.74/MWh in June, €53.29/MWh in July and €61.55/MWh in August. The provisional September average through Sept. 5 reached around €71.49/MWh. The rise amounts to almost a 60% increase from June to early September.
The shift reverses earlier summer expectations that improved LNG availability would lower European prices ahead of winter. Market changes were linked to developments in the global LNG market rather than a single regional factor. Renewed conflict around the Gulf and restrictions affecting Qatari LNG exports increased competition for flexible cargoes as Europe sought to rebuild depleted storage.
Storage levels and seasonal demand outlook
Hot weather added demand by increasing gas-fired power generation across Southern and Southeast Europe. This weakened the usual summer pattern in which lower prices support storage injections before the heating season. EU underground storage was about 66% full on Sept. 4, holding roughly 747 TWh, compared with around 79% at the same point last year and a historical level above 80%.
Storage conditions across Southeast Europe were mixed but generally stronger than those of Germany and the Netherlands. Hungary was near 70% full, Romania 72%, Croatia close to 75% and Bulgaria around 63% in early September. While these inventories provide a buffer, they do not prevent regional exposure to European hub pricing because imported gas and replacement LNG are still set against international markets.
The European Commission said there is no immediate security-of-supply threat, citing lower structural demand, expanded LNG capacity and greater diversification since the 2022 energy crisis. The market is nonetheless pricing a tighter winter starting point, which matters for Southeast Europe’s gas procurement and power generation planning. Cooling demand is also expected to ease from August levels if weather normalises.
Greece’s LNG role and electricity-linked gas demand
Greece has become central to regional supply diversification as LNG flows expanded through its terminals. Greek LNG imports through Revythoussa and Alexandroupolis reached about 27.9 TWh in the first eight months of 2026, up almost 32% year on year and a record for the period. In August, Alexandroupolis LNG imports more than doubled month on month to about 1.13 TWh, offsetting weaker deliveries through Revythoussa.
Alongside LNG, Russian pipeline gas entering Greece through Sidirokastro rose to 2.62 TWh in August, its highest monthly level this year. Azerbaijani gas entering via the TAP-linked Nea Mesimvria entry point fell sharply over the same period. The changes reflected a broader portfolio rather than direct substitution between sources.
Greece also exported about 11.9 TWh of gas during the first eight months of 2026, a three-year high that supports its role as both consumer and transit market. Gas use in Greek electricity generation remains a key element of that balance, with power plants consuming around 4.66 TWh in August—more than 80% of Greek domestic gas demand during the month.
Periods of weak hydro output, nuclear outages or low wind can increase gas-fired generation and tighten gas demand even outside the heating season . This linkage keeps regional gas fundamentals tied to electricity conditions during September and October.
Bulgaria’s regulated price and Western Balkans corridor integration
Bulgaria is an exception within the wider price move due to its regulated pricing framework. Its regulated September gas price was set at €41.60/MWh, up 5.5% from August but still substantially below international hub levels because lower-priced Azerbaijani gas contributes to the supply mix . That creates a potential cost advantage for Bulgarian heating companies and industrial consumers compared with buyers fully exposed to TTF-indexed supply.
The regulated price has still risen over the summer period, moving from €35.62/MWh in June to €41.60/MWh in September as cheaper supply shares declined . Beyond pricing, infrastructure developments have accelerated physical integration of the Western Balkans into the southern gas system during summer.
Serbia and North Macedonia formally joined the Vertical Gas Corridor on Sept. 4, extending cooperation between transmission operators from Greece and Bulgaria toward the Western Balkans . The Greece–North Macedonia interconnector is under construction, while North Macedonia has already contracted work on its section of the future connection with Serbia.
The infrastructure increases access to LNG arriving in Greece as well as Azerbaijani supply into the broader network, but it is expected to affect security and optionality rather than guarantee a price discount for end users . For September trading, market activity is expected to balance softer seasonal demand against continued storage buying.
Forward curve scenarios for September and October
Current forward pricing around €70–72/MWh for September and October reflects this balance between reduced cooling-related demand and ongoing requirements for injections before winter . A base case described for European and hub-linked SEE gas is broadly a €65–80/MWh range through September, with large day-to-day moves linked to LNG shipping conditions and Middle East headlines.
October should normally reduce cooling demand but introduces the first meaningful heating load, bringing markets closer to storage withdrawal season . The forward curve does not price a major autumn collapse, with October gas still near €71/MWh; if Gulf LNG flows stabilise and temperatures remain mild in September, prices could move back toward €55–65/MWh .
The main upside scenario involves more severe disruption: a prolonged Qatari LNG disruption combined with an early cold period and continued low storage could push TTF toward €85–100/MWh, particularly if Europe needs to outbid Asia for flexible cargoes . Exposure across Southeast Europe would remain uneven due to differences in contracted supply positions and domestic production.
Bulgaria is expected to retain some protection from contracted Azerbaijani supply while Romania benefits from substantial domestic production . Greece would remain more directly exposed to LNG economics despite having a diversified terminal system that supports physical security and growing transit value; Hungary and Serbia retain access to Russian gas through the southern route while building alternatives via Greece and Bulgaria .
The immediate risk for September and October is framed less around whether molecules can reach Southeast Europe than around what price must be paid for flexible supply when European storage is low and global LNG competition tightens . With TTF around €70/MWh, flexible gas-fired plants enter autumn with higher short-run costs than at the start of summer; if hydro and nuclear availability stay weak, that level can increasingly influence evening power pricing across Southeast Europe through September and October .
Research verification: European storage was about 66.1% on Sept. 4 (Hungary near 70%, Romania 72%, Bulgaria 63%, Croatia 75%). TTF’s summer trajectory rose from €44.74/MWh in June to €53.29 in July, €61.55 in August and about €71.49 for early September; Greek LNG, consumption and export figures are based on DESFA-derived August data; Bulgaria’s September regulated price is €41.60/MWh; Serbia and North Macedonia formally joined the Vertical Gas Corridor on Sept. 4.
